UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 6-K

Report of Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

Dated  August 2, 2012

Commission file number 001-15254

ENBRIDGE INC.

(Exact name of Registrant as specified in its charter)

3000, 425 – 1st Street S.W.

Calgary, Alberta, Canada  T2P 3L8

(Address of principal executive offices and postal code)

(403) 231-3900

(Registrants telephone number, including area code)

Indicate by check mark whether the Registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by regulation S-T Rule 101(b)(7):

Indicate by check mark whether the Registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

If “Yes” is marked, indicate below the file number assigned to the Registrant in connection with Rule 12g3-2(b):

N/A

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NO. 333-145236, 333-127265, 333-13456, 333-97305 AND 333-6436), FORM F-3 (FILE NO. 33-77022) AND FORM F-10 (FILE NO. 333-181333) OF ENBRIDGE INC. AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

The following documents are being submitted herewith:

·                Press Release dated August 2, 2012

·                Interim Report to Shareholders for the six months ended June 30, 2012.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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NEWS RELEASE

Enbridge reports second quarter adjusted earnings of $277 million or $0.36 per common share

HIGHLIGHTS

(all financial figures are unaudited and in Canadian dollars)

·                  Second quarter earnings were $11 million; six month earnings were $275 million including unrealized non-cash mark-to-market losses

·                  Second quarter and six months adjusted earnings increased 7% to $277 million and 11% to $653 million, respectively

·                  Enbridge announced $3.2 billion of additional Eastern Access and Mainline Expansion projects

·                  Seaway Pipeline reversal was completed providing an initial 150,000 barrels per day of crude oil transportation capacity from Cushing, Oklahoma to the United States Gulf Coast

·                  Enbridge continued the execution of its financing plan with the issuance of $1.06 billion in preference shares, $0.4 billion in common shares and a unique $0.1 billion “century” bond with a term of 100 years

·                  Silver State North Solar Project and Greenwich Windfarm celebrated grand openings

·                  Enbridge responds to the National Transportation Safety Board report on the July 2010 Michigan crude oil release; and to the July 27, 2012 crude oil release in Wisconsin

CALGARY, ALBERTA, August 2, 2012 – Enbridge Inc. (TSX:ENB) (NYSE:ENB) – “Over the first half of 2012, Enbridge has continued to deliver steady performance, keeping us on track with our full year adjusted earnings per share guidance range of $1.58 to $1.74,” said Patrick D. Daniel, Chief Executive Officer.

2012 results reflected unrealized non-cash mark-to-market accounting impacts related to the comprehensive long-term economic hedging program Enbridge has put in place to mitigate exposures to interest rate variability and foreign exchange, as well as commodity price risks. These kinds of short-term non-cash impacts to reported earnings are a result of Enbridge’s hedging program, which the Company believes over the long-term will support reliable cash flows and dividend growth.

In May, Enbridge announced a suite of major additions to its liquids pipelines infrastructure, totaling $3.2 billion. Enbridge has secured commercial support to proceed with additional Eastern Access projects including a 80,000 barrel per day (bpd) expansion of Enbridge’s Toledo Pipeline (Line 17) and a re-reversal of Enbridge’s 240,000 bpd Line 9B from Westover, Ontario to Montreal, Quebec. Enbridge and Enbridge Energy Partners, L.P. (EEP) also expect to proceed with supporting expansions of the United States mainline system between Flanagan, Illinois and Sarnia, Ontario, and expansion of Line 67 (Alberta Clipper) and Line 61 (Southern Access).

“Our Eastern Access projects complement our previously announced Gulf Coast Access projects in expanding access to new markets in North America for growing production from western Canada and the Bakken,” said Mr. Daniel. “These market access projects and the supporting mainline expansions are

Forward-Looking Information

This news release contains forward-looking information. Significant related assumptions and risk factors are described under the Forward-Looking Information section of this news release.

attractive investment opportunities for Enbridge and EEP. The associated aggregate investment of approximately $8 billion at attractive returns provides substantial support for the extension of our 10% growth rate in adjusted earnings per share through the middle of this decade and beyond.”

Mr. Daniel noted that Enbridge’s expansion projects will also provide substantial economic benefits to shippers and the local economies in western Canada and the Bakken region in North Dakota where the crude oil is produced, as well as in the midwestern United States and eastern Canada where it will be refined.

“Communities along the routes of these pipelines will also benefit from increased economic activity. Importantly, these initiatives utilize existing energy corridors and pipelines that minimize disruption to the environment and lessen the industry’s footprint.”

Enbridge and its partner, Enterprise Products Partners, L.P. (Enterprise), marked a significant milestone with oil first flowing May 19, 2012 on the reversed Seaway Pipeline for delivery to the United States Gulf Coast.

“We continue to make excellent progress in establishing a new and much needed corridor from the Chicago area to the United States Gulf Coast refining market,” said Mr. Daniel. “With the completion of the first phase of the reversal and expansion of the Seaway Pipeline we’ve now added 150,000 bpd of new capacity out of the Cushing hub and we expect to ramp this up to 400,000 bpd by the beginning of 2013. Our Flanagan South Pipeline Project and existing Spearhead Pipeline System, combined with the planned twinning of the Seaway Pipeline, will bring total capacity from Chicago to the United States Gulf Coast to approximately 850,000 bpd by mid-2014, with low cost expandability beyond that. This will help to relieve bottlenecks arising from an unprecedented growth outlook for North American oil production, reduce price discounts for producers and further reduce United States dependence on overseas imports.”

Over the quarter, Enbridge continued to be active in equity markets and building liquidity in support of the Company’s suite of investment opportunities, placing approximately $610 million in preference shares; with a subsequent issue in July raising an additional $450 million. During the quarter, the Company was also successful in issuing 9.83 million common shares for gross proceeds of approximately $400 million.

“In July, confidence in the long-term sustainability of Enbridge’s business model was demonstrated by the issuance of a $100 million Century Bond with a 100-year term to maturity through its subsidiary, Enbridge Pipelines Inc., the second Century Bond ever issued by a Canadian corporation,” said Mr. Daniel. Also in July, a new US$675 million credit facility was secured by EEP, bringing Enbridge’s enterprise wide general purpose credit facilities to $11.8 billion.

In green energy, Enbridge celebrated grand openings at the Silver State North Solar Project (Silver State) in Nevada on May 7, 2012 and at the Greenwich Windfarm in Ontario on June 15, 2012.

“We’re pleased to continue to advance our growth strategy in renewable and alternative energy generation, creating environmental benefits while generating stable and reliable cash flows,” said Mr. Daniel. “Since 2002, Enbridge has invested nearly $3 billion in its growing North American portfolio of renewable and alternative energy technologies which now includes eight wind farms, four solar projects, a geothermal installation, a hybrid fuel cell and four waste heat recovery facilities.”

“Enbridge currently has in place the largest slate of attractive commercially secured growth projects in the history of the Company, supported by a team ready to execute and to lead the Company into the next stage of its development. As we enter the latter half of 2012, we remain confident in our ability to achieve our strategic objectives and to continue to deliver superior results to our shareholders,” concluded Mr. Daniel.

In early July, the National Transportation and Safety Board (NTSB) issued a summary of its report on the July 2010 crude oil leak in Michigan, followed shortly after by publication of its final report.

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On July 27, 2012, Enbridge confirmed a crude oil release on Line 14, owned by Enbridge Energy, Limited Partnership, a subsidiary of EEP, near Grand Marsh, Wisconsin. Enbridge continues to make significant clean up and restoration progress at the site and is committed to thorough restoration as quickly as possible. Repair of Line 14 is complete; however, the date for Line 14 to return to service is indeterminate at this time. Enbridge will work with the Pipeline and Hazardous Materials Safety Administration (PHMSA) to meet all requirements that must be satisfied prior to the restart of the line and will work with shippers to mitigate the impact of this disruption to the maximum extent possible.

“At the time of the Marshall incident in July 2010, we immediately accepted full responsibility and committed to do whatever it took to make things right in the community, to fully understand what happened, and to do what was necessary to work with all parties to improve procedures and technology so that this wouldn’t happen again,” said Mr. Daniel. “While we deeply regret the incident on Line 14 this past week, our ability to quickly detect and immediately respond to the leak thus limiting environmental impacts is evidence of our ongoing commitment to implement the learnings from 2010 and the enhancements we’ve made over the past two years. We will continue to carefully examine the report of the NTSB, as well as the findings from the investigation of the Line 14 leak, to determine whether any further changes are required. We apologize to those affected by the Line 14 incident and we greatly appreciate the patience and cooperation of the affected landowners and the community.

“Operational safety and reliability are our highest priorities,” continued Mr. Daniel. “We are humbled by the incidents we have experienced. Under the framework of our comprehensive Operational Risk Management plan, we are applying our learnings, and have set for ourselves the objective of delivering industry leading performance across all of our existing operations. We will design and build our growth projects to meet and exceed the expectations of our stakeholders for the safe and reliable delivery of energy.

SECOND QUARTER 2012 OVERVIEW

For more information on Enbridge’s growth projects and operating results, please see the Management’s Discussion and Analysis (MD&A) which is filed on SEDAR and EDGAR and also available on the Company’s website at www.enbridge.com/InvestorRelations.aspx.

·                  Earnings attributable to common shareholders of $11 million for the second quarter of 2012 have decreased compared with the second quarter of 2011 primarily due to the recognition of net unrealized fair value losses on financial derivatives used to risk manage the profitability of forward transportation and storage transactions and revaluation of inventory in Energy Services, as well as foreign exchange and commodity price risks inherent within the Competitive Toll Settlement.

·                  Enbridge’s second quarter adjusted earnings increased 7% to $277 million as a result of increased contributions from Canadian Mainline and Spearhead Pipeline, which benefited from strong volumes, partially offset by decreased earnings from Enbridge Gas New Brunswick (EGNB) and increased net Corporate segment financing costs.

·                  On July 27, 2012, a release of crude oil was detected on Line 14 of EEP’s Lakehead System near Grand Marsh, Wisconsin. After detecting a pressure drop on Line 14, Line 14 was immediately shut down and isolated and emergency crews were promptly dispatched. The initial estimate of volume of the oil released was approximately 1,200 barrels. EEP estimates that its costs associated with repair of the pipeline and remediation of this crude oil release will be approximately US$8 million based on currently available information. Despite the efforts EEP has made to ensure the reasonableness of its estimate, changes to the estimated amounts associated with this release are possible as more reliable information becomes available. Enbridge received a Corrective Action Order (CAO) from the Pipeline and Hazardous Materials Safety Administration (PHMSA) on July 30, 2012 and a follow on amendment to the CAO on August 1, 2012 outlining additional requirements that must be satisfied prior to the restart of Line 14. A substantial portion of the additional requirements are consistent with actions already planned and being implemented by Enbridge. Enbridge will review the requirements, adjust its plans as required, and work with PHMSA to satisfy all of the specified requirements on a timely basis. The date for Line 14 to return to service remains indeterminate until such work is further progressed. Enbridge will work with shippers to mitigate impacts to crude oil supply to midwestern United States refineries to the maximum extent possible. Enbridge does not anticipate the financial impact of a period of suspended service on Line 14 will be material.

·                  On July 10, 2012, theNTSB discussed the results of its investigation into the Line 6B crude oil release that occurred near Marshall, Michigan in July 2010 and subsequently posted its final report on July 26, 2012. Enbridge and EEP have worked closely and cooperatively with the NTSB throughout its investigation, and are now reviewing the report. Further on July 2, 2012, EEP and Enbridge received a Notice of Probable Violation (NOPV) from the PHMSA regarding this incident, which indicated a US$3.7 million civil penalty. Enbridge has worked closely and cooperatively with all federal and state agencies, including PHMSA, throughout the investigation of the Line 6B accident, and is now reviewing the NOPV in detail.

·                  On June 19, 2012, Enbridge confirmed an oil release at its Elk Point oil pumping station on Line 19 (Athabasca Pipeline), approximately 70 kilometres (44 miles) south of Bonnyville, Alberta and approximately 24 kilometres (15 miles) from the town of Elk Point. The release, which occurred June

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18, 2012, was largely contained within the pumping station site with no risk to public health or safety. The area was secured and clean-up operations began immediately. Volume estimates of the release are approximately 1,400 barrels. After receiving approval from the Energy Resources Conservation Board (ERCB), Enbridge safely restarted the Elk Point pumping station on June 24, 2012. The ERCB and Enbridge are continuing their investigations as to the cause of the incident which appears to be the failure of a flange gasket.

·                  Enbridge and Renewable Energy Systems Canada Inc. (RES Canada), an affiliate of RES Americas, celebrated the grand opening of Enbridge’s 99-megawatt (MW) Greenwich Windfarm on June 15, 2012. Located on the northern shore of Lake Superior, the 99 MW project is expected to generate enough clean electricity to meet the needs of about 34,000 households, potentially displacing about 107,000 tonnes of carbon dioxide emissions annually. It is the first wind power facility to be wholly located on Crown land in Ontario. The Greenwich Windfarm delivers energy to the Ontario Power Authority under a Renewable Energy Supply III (RES III) 20-year power purchase agreement. Comprising 43 Siemens SWT-2.3 wind turbines, the project was constructed by RES Canada under a fixed price, turnkey, engineering, procurement and construction agreement.

·                  Enbridge and Enterprise announced on May 19, 2012 that the Seaway Pipeline began accepting crude oil at Cushing, Oklahoma for delivery to the United States Gulf Coast. The reversal of the 805-kilometre (500-mile), 30-inch diameter pipeline, which had been in northbound service since 1995, provides North American producers with the infrastructure needed to access more than four million bpd of Gulf Coast refinery demand. The reversal will initially provide 150,000 bpd of capacity, which is expected to increase to more than 400,000 bpd in the first quarter of 2013 with additional modifications and increased pumping capabilities.

·                  On May 16, 2012, Enbridge announced it had secured commercial support to proceed with additional Eastern Access projects totaling up to approximately $2.6 billion. The Eastern Access initiative includes an 80,000 bpd expansion of the Toledo Pipeline, a reversal of the 240,000 bpd Line 9B from Westover, Ontario to Montreal, Quebec and the previously announced reversal of Line 9A from Sarnia, Ontario to Westover. Enbridge and EEP also expect to proceed with supporting expansions of the United States mainline system between Flanagan, Illinois and Sarnia, Ontario. The supporting mainline expansions include expansion of the Spearhead North pipeline between Flanagan and Griffith, Indiana, an additional 330,000 barrel tank at Griffith, replacement of additional sections of Line 6B in Indiana and Michigan, as well as the previously announced Line 5 expansion.

·                  On May 16, 2012, Enbridge and EEP announced approximately US$0.4 billion of projects to expand capacity of the Lakehead System mainline between its origin near Neche, North Dakota, to its growing terminal hub in Flanagan, Illinois, southwest of Chicago. The current scope of the projects includes expansion of the Alberta Clipper pipeline (Line 67) between the border and Superior, Wisconsin from 450,000 bpd to 570,000 bpd and expansion of the Southern Access pipeline (Line 61) between Superior and Flanagan, Illinois from 400,000 bpd to 560,000 bpd. Both projects require only the addition of pumping horsepower, with no line pipe construction. The scope of the expansions remains under discussion with shippers, which could lead to an upward revision to capacity and cost.

·                  Also on May 16, 2012, Enbridge announced an approximately $0.2 billion expansion of the Canadian portion of the Alberta Clipper pipeline (Line 67). The current scope of the project will involve the addition of pumping horsepower sufficient to raise the capacity of the Canadian mainline by 120,000 bpd. The expansion remains subject to National Energy Board approval and to finalization of scope and approval by shippers, which could lead to an upward revision of capacity and cost.

·                  On May 7, 2012, Enbridge celebrated the grand opening of the 50-MW Silver State project in Clark County, Nevada. The facility was acquired in March 2012 at an estimated cost of US$0.2 billion. Located 65 kilometers (40 miles) south of Las Vegas, Nevada, Silver State was constructed under a fixed-price engineering, procurement and construction agreement with First Solar. First Solar is providing operations and maintenance services under a long-term contract and the energy output is being delivered to NV Energy, Inc. under a 25-year power purchase agreement.

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·                  On April 16, 2012, the Government of New Brunswick enacted a final rates and tariffs regulation which set limits on gas distribution rates within the province. Enbridge had advised on March 12, 2012, when the regulation was still in draft form, that it faced a potential write down of a significant portion of the value of its investment in EGNB, the New Brunswick gas distribution utility. With the finalization of the regulation, Enbridge confirmed a write down of $262 million. The impact of this charge was recognized as a subsequent event in the Company’s 2011 United States generally accepted accounting principles (U.S. GAAP) consolidated financial statements, which were filed on May 2, 2012.

On April 26, 2012, the Company, Enbridge Energy Distribution Inc. (EEDI) and EGNB, commenced an action against the Province of New Brunswick in the New Brunswick Court of Queen’s Bench, claiming damages in the amount of $650 million as a result of the continuing breaches by the province of the General Franchise Agreement it signed with Enbridge in 1999. Additionally, on May 2, 2012, the Company, EEDI and EGNB filed a Notice of Application with the New Brunswick Court of Queen’s Bench seeking a declaration from the Court that the rates and tariffs regulation is invalid. The Application was heard by the Court on July 24, 2012, but no decision has yet been released. There is no assurance these actions will be successful or will result in any recovery.

·                  Since the end of the first quarter, the Company completed the following financing transactions:

·                  On July 18, 2012, Enbridge issued a $100 million Century Bond with a term to maturity of 100 years through its subsidiary, Enbridge Pipelines Inc., the second Century Bond ever issued by a Canadian corporation.

·                  On July 17, 2012, Enbridge completed an offering of Cumulative Redeemable Preference Shares, Series N. Due to strong investor demand, the size of the offering was increased to 18 million shares, for aggregate gross proceeds of $450 million.

·                  On July 6, 2012, a new US$675 million of credit facility was secured by EEP, bringing Enbridge’s enterprise-wide general purpose credit facilities to $11.7 billion.

·                  On June 8, 2012, Enbridge completed a public offering of 9.83 million common shares for gross proceeds of approximately $400 million.

·                  On May 23, 2012, Enbridge completed an offering of Cumulative Redeemable Preference Shares, Series L. Due to strong investor demand, the size of the offering was increased to 16 million shares, for aggregate gross proceeds of US$400 million.

·                  On April 19, 2012, Enbridge announced the completion of the issue of eight million Cumulative Redeemable Preference Shares, Series J for aggregate gross proceeds of US$200 million.

DIVIDEND DECLARATION

On August 1, 2012, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on September 1, 2012 to shareholders of record on August 15, 2012.

1                  This is the first dividend declared for Preference Shares, Series H.

2                  This is the first dividend declared for Preference Shares, Series J.

3                  This is the first dividend declared for Preference Shares, Series L.

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CONFERENCE CALL

Enbridge will hold a conference call on Thursday, August 2, 2012 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to discuss the second quarter 2012 results. Analysts, members of the media and other interested parties can access the call at 617-597-5313 or toll-free at 1-866-362-4666 using the access code of 40728322. The call will be audio webcast live at www.enbridge.com/InvestorRelations/Events.aspx. A webcast replay and podcast will be available approximately two hours after the conclusion of the event and a transcript will be posted to the website within 24 hours. The replay at toll-free 1-888-286-8010 or 617-801-6888 (access code 46996724) will be available until August 9, 2012.

The conference call will begin with presentations by the Company’s Chief Executive Officer, the President and the Chief Financial Officer, followed by a question and answer period for investment analysts. A question and answer period for members of the media will then immediately follow.

The unaudited interim Consolidated Financial Statements and MD&A, which contain additional notes and disclosures, are available on the Enbridge website at www.enbridge.com/InvestorRelations.aspx.

Enbridge Inc., a Canadian company, is a North American leader in delivering energy and one of the Global 100 Most Sustainable Corporations. As a transporter of energy, Enbridge operates, in Canada and the U.S., the world’s longest crude oil and liquids transportation system. The Company also has a significant and growing involvement in the natural gas gathering transmission and midstream businesses, and an increasing involvement in power transmission. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company, and provides distribution services in Ontario, Quebec, New Brunswick and New York State. Enbridge employs more than 7,000 people, primarily in Canada and the U.S., and is ranked as one of Canada’s Greenest Employers and one of the Top 100 Companies to Work for in Canada. Enbridge’s common shares trade on the Toronto and New York stock exchanges under the symbol ENB. For more information, visit www.enbridge.com. None of the information contained in, or connected to, Enbridge’s website is incorporated in or otherwise part of this news release.

Forward-Looking Information

Forward-looking information, or forward-looking statements, have been included in this news release to provide the Company’s shareholders and potential investors with information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’ and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to: expected earnings or adjusted earnings; expected earnings or adjusted earnings per share; expected costs related to projects under construction; expected in-service dates for projects under construction; expected capital expenditures; estimated future dividends; and expected costs related to leak remediation and potential insurance recoveries.

Although Enbridge believes that these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about: the expected supply and demand for crude oil, natural gas and natural gas liquids (NGL); prices of crude oil, natural gas and NGL; expected exchange rates; inflation; interest rates; the availability and price of labour and pipeline construction materials; operational reliability; customer project approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; and weather. Assumptions regarding the expected supply and demand of crude oil, natural gas and NGL, and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates,

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may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings or adjusted earnings and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated in-service dates, and expected capital expenditures include: the availability and price of labour and pipeline construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer and regulatory approvals on construction schedules.

Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to operating performance, regulatory parameters, project approval and support, weather, economic and competitive conditions, exchange rates, interest rates, commodity prices and supply and demand for commodities, including but not limited to those risks and uncertainties discussed in this news release and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this news release or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.

Non-GAAP Measures

This news release contains references to adjusted earnings/(loss), which represent earnings or loss attributable to common shareholders adjusted for non-recurring or non-operating factors on both a consolidated and segmented basis. These factors are reconciled and discussed in the financial results sections for the affected business segments. Management believes that the presentation of adjusted earnings/(loss) provides useful information to investors and shareholders as it provides increased transparency and predictive value. Management uses adjusted earnings/(loss) to set targets, assess performance of the Company and set the Company’s dividend payout target. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a standardized meaning prescribed by U.S. GAAP and are not considered GAAP measures; therefore, these measures may not be comparable with similar measures presented by other issuers.

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HIGHLIGHTS

1                  Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011.

2                  Adjusted earnings represent earnings attributable to common shareholders adjusted for non-recurring or non-operating factors. Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by GAAP.

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3                  Canadian Mainline includes deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western Canada.

4                  Volumes are for the Athabasca mainline and Waupisoo Pipeline and exclude laterals on the Regional Oil Sands System.

5                  Number of active customers is the number of natural gas consuming EGD customers at the end of the period.

6                  Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in EGD’s franchise area. It is calculated by accumulating, for the fiscal period, the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius. The figures given are those accumulated in the Greater Toronto Area.

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ENBRIDGE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS

June 30, 2012

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2012

This Management’s Discussion and Analysis (MD&A) dated August 1, 2012 should be read in conjunction with the unaudited consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) as at and for the three and six months ended June 30, 2012, prepared in accordance with United States generally accepted accounting principles (U.S. GAAP). It should also be read in conjunction with the audited consolidated financial statements, which were prepared in accordance with Part V – Pre-changeover Accounting Standards of the Canadian Institute of Chartered Accountants Handbook (Part V), and MD&A contained in the Company’s Annual Report for the year ended December 31, 2011, as well as the consolidated financial statements for the year ended December 31, 2011 that were prepared in accordance with U.S. GAAP and filed on a voluntary basis to facilitate understanding of the Company’s transition to U.S. GAAP. All financial measures presented in this MD&A are expressed in Canadian dollars, unless otherwise indicated. Additional information related to the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com.

CONSOLIDATED EARNINGS

1                  Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011.

Earnings attributable to common shareholders were $11 million for the three months ended June 30, 2012, or $0.01 per common share, compared with $302 million, or $0.40 per common share, for the three months ended June 30, 2011. This decrease primarily reflected the recognition of net unrealized fair value losses on financial derivatives compared with net unrealized gains for the prior period. The Company uses derivatives to manage exposures to interest rate variability and foreign exchange and commodity price risks. The most significant change, recognized in Energy Services, related to the revaluation of financial derivatives used to risk manage the profitability of forward transportation and storage transactions, and revaluation of inventory. Partially offsetting these quarter-over-quarter declines were increased earnings from Liquids Pipelines as a result of strong volumes and favourable operating performance under the Competitive Toll Settlement (CTS).

Earnings attributable to common shareholders were $275 million for the six months ended June 30, 2012, or $0.36 per common share, compared with $666 million, or $0.89 per common share, for the six months ended June 30, 2011. The decrease in year-to-date earnings reflected the same drivers as the second quarter, with increased earnings from Enbridge Income Fund (the Fund) partially offsetting the decrease. This earnings increase primarily resulted from strong contributions from the Fund’s increased investment in renewable assets.

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FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this MD&A to provide the Company’s shareholders and potential investors with information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’ and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to: expected earnings or adjusted earnings; expected earnings or adjusted earnings per share; expected future cash flows; expected costs related to projects under construction; expected in-service dates for projects under construction; expected capital expenditures; estimated future dividends; and expected costs related to leak remediation and potential insurance recoveries.

Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about: the expected supply and demand for crude oil, natural gas and natural gas liquids (NGL); prices of crude oil, natural gas and NGL; expected exchange rates; inflation; interest rates; the availability and price of labour and pipeline construction materials; operational reliability; customer project approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; and weather. Assumptions regarding the expected supply and demand of crude oil, natural gas and NGL, and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates, may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings or adjusted earnings and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated in-service dates, and expected capital expenditures include: the availability and price of labour and pipeline construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer and regulatory approvals on construction schedules.

Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to operating performance, regulatory parameters, project approval and support, weather, economic and competitive conditions, exchange rates, interest rates, commodity prices and supply and demand for commodities, including but not limited to those risks and uncertainties discussed in this MD&A and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.

NON-GAAP MEASURES

This MD&A contains references to adjusted earnings/(loss), which represent earnings or loss attributable to common shareholders adjusted for non-recurring or non-operating factors on both a consolidated and segmented basis. These factors are reconciled and discussed in the financial results sections for the affected business segments. Management believes that the presentation of adjusted earnings/(loss) provides useful information to investors and shareholders as it provides increased transparency and predictive value. Management uses adjusted earnings/(loss) to set targets, assess performance of the Company and set the Company’s dividend payout target. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a standardized meaning prescribed by U.S. GAAP and are not considered GAAP measures; therefore, these measures may not be comparable with similar measures presented by other issuers. See Non-GAAP Reconciliations for a reconciliation of the GAAP and non-GAAP measures.

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ADJUSTED EARNINGS

1                  Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011.

Adjusted earnings were $277 million, or $0.36 per common share, for the three months ended June 30, 2012 compared with $258 million, or $0.34 per common share, for the three months ended June 30, 2011. Adjusted earnings were $653 million, or $0.86 per common share, for the six months ended June 30, 2012 compared with $588 million, or $0.78 per common share, for the six months ended June 30, 2011. The following factors impacted the increase in adjusted earnings for both the three and six months ended June 30, 2012 compared with 2011.

·                  Within Liquids Pipelines, increased contributions from Canadian Mainline and Spearhead Pipeline, both of which benefited from strong volumes. Incremental oil sands crude production in Alberta and strong production growth out of the Bakken in North Dakota have bolstered supply to midwest markets, and placed increased downward pressure on crude oil prices in the midwest, pending completion of Enbridge’s market access projects. This discounted crude oil, coupled with strong refining margins, is increasing demand in the midwest for Canadian and Bakken crude oil supply and driving increased long haul barrels on Canadian Mainline and Enbridge Energy Partners, L.P.’s (EEP) Lakehead System.

·                  Continued positive performance at Enbridge Gas Distribution (EGD) reflecting favourable operating performance under the current Incentive Regulation term was more than offset for the three months by decreased earnings from Other Gas Distribution and Storage, including from Enbridge Gas New Brunswick (EGNB). Under the new regulations to which EGNB is subject, rate regulated accounting no longer applies. EGNB earnings will be reduced and will fluctuate with variations in seasonal demand.

·                  EEP adjusted earnings primarily reflected higher volumes on all major liquids systems, offset for the three months by lower NGL prices.

·                  Increased contributions from the Fund due to the acquisition and strong operating performance of certain renewable energy assets, partially offset by increased financing costs and deferred income taxes.

·                  In Corporate, higher net Corporate segment financing costs, inclusive of preference share dividends.

RECENT DEVELOPMENTS

CHIEF EXECUTIVE OFFICER SUCCESSION PLANS

On February 27, 2012, the Board of Directors announced that Patrick D. Daniel, then President and Chief Executive Officer (CEO), will retire at or before the end of 2012. The Board also announced the appointment of Al Monaco, previously President, Gas Pipelines, Green Energy and International, to Enbridge’s Board of Directors and to the position of President, effective February 27, 2012. Mr. Daniel will continue as CEO and a member of the Board until his retirement. With Mr. Monaco’s appointment as President of Enbridge, Leon Zupan was appointed President, Gas Pipelines.

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LIQUIDS PIPELINES

Southern Lights Pipeline

Both the Canadian and United States uncommitted rates on Southern Lights Pipeline for 2010, 2011 and 2012 were challenged by Exxon Mobil and Imperial Oil. The Canadian Southern Lights toll hearing was held before National Energy Board (NEB) panel members in November 2011. On February 9, 2012, the NEB issued its decision rejecting the challenge from uncommitted shippers stating that tolls in place are just and reasonable, and more recently approved the 2010, 2011 and 2012 interim tolls as final. A Federal Energy Regulatory Commission (FERC) hearing was held in January 2012. Briefs were filed on February 27, 2012 and March 28, 2012 and an initial decision was issued on June 5, 2012. The initial decision found that the uncommitted rates were just and reasonable. The parties will file briefs in response to this decision and the case will then be sent to the FERC for a final decision. No material financial impact to the Company is anticipated to result from the FERC proceeding.

Elk Point Pump Station Facility Oil Release

On June 19, 2012, Enbridge reported an oil release at its Elk Point pumping station on Line 19 (Athabasca Pipeline), approximately 70 kilometres (44 miles) south of Bonnyville, Alberta and approximately 24 kilometres (15 miles) from the town of Elk Point, Alberta. On June 24, 2012, the Company restarted the Elk Point pumping station after completing necessary repairs. The majority of contaminated soil and free product has been removed from the site for processing and disposal. Further environmental testing and monitoring of the site is being conducted. Volume estimates of the release are approximately 1,400 barrels which were largely contained within the station. Management does not believe this incident will have a material impact on the Company’s consolidated financial position or results of operations.

Norman Wells Pipeline Crude Oil Release

On May 9, 2011, Enbridge reported a crude oil release from the Norman Wells Pipeline approximately 50 kilometres (31 miles) south of the community of Wrigley, Northwest Territories (NWT). The Norman Wells Pipeline is a 12-inch, 39,400 barrels per day (bpd) line transporting sweet crude oil that stretches 869 kilometres (540 miles) from Norman Wells, NWT to Zama, Alberta. On May 20, 2011, Enbridge returned the Norman Wells line to service after completing necessary repairs. Excavation of all contaminated soils from the spill site was completed in late November 2011. Based on the volume of contaminated materials removed from the site, the current estimate of volume released is approximately 1,600 barrels. Site reclamation work is anticipated to be completed in the summer of 2012. Monitoring of surface water and groundwater at the site will continue until remediation and reclamation goals have been achieved in accordance with plans filed with the regulator. Management does not believe this incident will have a material impact on the Company’s consolidated financial position or results of operations.

GAS DISTRIBUTION

Enbridge Gas New Brunswick – Regulatory Matters

On December 9, 2011 the Government of New Brunswick tabled and subsequently passed legislation related to the regulatory process for setting rates for gas distribution within the province. The legislation permitted the government to implement new regulations which could affect the franchise agreement between EGNB and the province, impact prior decisions by the province’s independent regulator and influence the regulator’s future decisions. However, significant details of the rate setting process were left to be established in the new regulations and, as such, the effect of such legislation was not determinable at that time.

A final rates and tariffs regulation was subsequently enacted by the Government of New Brunswick on April 16, 2012. Based on the amendments to the rate setting methodology outlined therein, EGNB no longer meets the criteria for the continuation of rate regulated accounting. As a result, the Company must eliminate from its consolidated statements of financial position a deferred regulatory asset of $180 million and a regulatory asset with respect to capitalized operating costs of $103 million, net of an income tax recovery of $21 million.

As the final rates and tariffs regulation published on April 16, 2012 provided further evidence of a condition that existed on December 31, 2011, recognition of the charge totaling $262 million, after tax,

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was reflected as a subsequent event in the Company’s U.S. GAAP consolidated financial statements for the year ended December 31, 2011, which were filed with the Canadian Securities Administrators and the United States Securities and Exchange Commission (SEC) on May 2, 2012. The charge reflects Management’s best estimate based on facts available at this time and may be subject to further revision based on future actions or interpretations of the regulator, the Government of New Brunswick or other factors, including judicial proceedings which Enbridge has commenced, as referred to below.

On April 26, 2012, the Company, Enbridge Energy Distribution Inc. (EEDI) and EGNB commenced an action against the Province of New Brunswick in the New Brunswick Court of Queen’s Bench, claiming damages in the amount of $650 million as a result of the continuing breaches by the province of the General Franchise Agreement it signed with Enbridge in 1999. Additionally, on May 2, 2012, the Company, EEDI and EGNB filed a Notice of Application with the New Brunswick Court of Queen’s Bench seeking a declaration from the Court that the rates and tariffs regulation is invalid. The Application was heard by the Court on July 24, 2012, but no decision has yet been released. There is no assurance these actions will be successful or will result in any recovery.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Greenwich Wind Energy Project

In May 2012, the Company acquired from Renewable Energy Systems Canada Inc. the remaining 10% interest in the Greenwich Wind Energy Project (Greenwich) through Greenwich Windfarm, LP, for $27 million, increasing its ownership to 100%.

SPONSORED INVESTMENTS

ENBRIDGE ENERGY PARTNERS, L.P.

Enbridge holds an approximate 23% combined direct and indirect ownership interest in EEP. Under U.S. GAAP, Enbridge consolidates EEP with its earnings, net of noncontrolling interests, reflected within the Sponsored Investments segment.

Lakehead System Line 14 Crude Oil Release

On July 27, 2012, a release of crude oil was detected on Line 14 of EEP’s Lakehead System near Grand Marsh, Wisconsin. After detecting a pressure drop on Line 14, Line 14 was immediately shut down and isolated and emergency crews were promptly dispatched. The initial estimate of volume of the oil released was approximately 1,200 barrels. EEP estimates that its costs associated with repair of the pipeline and remediation of this crude oil release will be approximately US$8 million based on currently available information. Despite the efforts EEP has made to ensure the reasonableness of its estimate, changes to the estimated amounts associated with this release are possible as more reliable information becomes available. Enbridge received a Corrective Action Order (CAO) from the Pipeline and Hazardous Materials Safety Administration (PHMSA) on July 30, 2012 and a follow on amendment to the CAO on August 1, 2012 outlining additional requirements that must be satisfied prior to the restart of Line 14. A substantial portion of the additional requirements are consistent with actions already planned and being implemented by Enbridge. Enbridge will review the requirements, adjust its plans as required, and work with PHMSA to satisfy all of the specified requirements on a timely basis. The date for Line 14 to return to service remains indeterminate until such work is further progressed. Enbridge will work with shippers to mitigate impacts to crude oil supply to midwestern United States refineries to the maximum extent possible. Enbridge does not anticipate the financial impact of a period of suspended service on Line 14 will be material.

Lakehead System Line 6A and 6B Crude Oil Releases

Line 6B Crude Oil Release

During the second quarter of 2012, cleanup of the areas affected by the Line 6B crude oil release that occurred in July 2010 near Marshall, Michigan allowed the Kalamazoo River and Morrow Lake to be re-opened for recreational use. EEP will continue to perform necessary remediation, restoration and monitoring of the areas affected by the Line 6B crude oil release. EEP expects to make payments for additional costs associated with submerged oil and sheen monitoring and recovery operations, including remediation and restoration of the area, air and groundwater monitoring, scientific studies and hydrodynamic modeling, along with legal, professional and regulatory costs through future periods. All the initiatives that EEP will undertake in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities.

On July 2, 2012, EEP received a Notice of Probable Violation (NOPV) from the PHMSA related to the Line 6B crude oil release, which indicated a US$3.7 million civil penalty. EEP included the amount of the penalty in its total estimated cost for the Line 6B crude oil release. In addition, on July 10, 2012 the National Transportation Safety Board presented the results of its investigation into the Line 6B crude oil release and subsequently posted its final report on July 26, 2012.

As a result of additional work needed as noted above and the civil penalty assessed by PHMSA, EEP has revised the total estimate for costs to US$785 million ($131 million after-tax attributable to Enbridge) for this incident, before insurance recoveries, and excluding fines and penalties which may be imposed by federal, state and local government agencies, other than the PHMSA civil penalty described above, as at June 30, 2012, an increase of US$20 million ($2 million after-tax attributable to Enbridge) from March 31, 2012. Expected losses associated with the Line 6B crude oil release include those costs that are considered probable and that could be reasonably estimated at June 30, 2012. Despite the efforts EEP has made to ensure the reasonableness of its estimates, there continues to be the potential for EEP to incur additional costs in connection with this crude oil release due to variations in any or all of the cost categories, including modified or revised requirements from regulatory agencies, in addition to fines and penalties and expenditures associated with litigation and settlement of claims.

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Line 6A Crude Oil Release

EEP continues to monitor the areas affected by the crude oil release from Line 6A of its Lakehead System near Romeoville, Illinois in September 2010 for any additional requirements; however, the cleanup, remediation and restoration of the areas affected by the release have been substantially completed.

In connection with this crude oil release, the cost estimate remains at US$48 million ($7 million after-tax attributable to Enbridge), before insurance recoveries and excluding fines and penalties.

EEP has the potential of incurring additional costs in connection with this crude oil release, including fines and penalties as well as expenditures associated with litigation. EEP is pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained.

Insurance Recoveries

EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates which renews in May of each year. The program includes commercial liability insurance coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents such as those incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties. The claims for the crude oil release for Line 6B are covered by Enbridge’s comprehensive insurance policy that expired on April 30, 2011, which had an aggregate limit of US$650 million for pollution liability. Based on EEP’s remediation spending through June 30, 2012, Enbridge and its affiliates have exceeded the limits of its coverage under this insurance policy. Additionally, fines and penalties would not be covered under the existing insurance policy.

In the first quarter of 2012, EEP received insurance payments of US$50 million ($7 million after-tax attributable to Enbridge) for insurance receivable claims previously recognized as a reduction to environmental costs in 2011. At June 30, 2012, EEP had collected total insurance recoveries of US$335 million ($50 million after-tax attributable to Enbridge) for the Line 6B crude oil release. EEP expects to record a receivable for additional amounts claimed for recovery pursuant to EEP’s insurance policies during the period that EEP deems realization of the claim for recovery to be probable. EEP recognized US$15 million ($3 million after-tax attributable to Enbridge) and US$50 million ($8 million after-tax attributable to Enbridge) of insurance recoveries for the three and six months ended June 30, 2011, respectively.

Effective May 1, 2012, Enbridge renewed its comprehensive insurance program, through April 30, 2013, with a current liability aggregate limit of US$660 million, including sudden and accidental pollution liability.

Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Line 6A and Line 6B crude oil releases. Approximately 25 actions or claims have been filed against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B crude oil release, including direct actions and actions seeking class status. Based on the current status of these cases EEP does not expect these actions to be material. On July 2, 2012, PHMSA announced a NOPV related to the Line 6B crude oil release, including a civil penalty of US$3.7 million. One claim related to the Line 6A crude oil release has been filed against Enbridge, EEP or their affiliates by the State of Illinois in a United States state court. The parties are currently operating under an agreed interim order.

Enbridge Income Fund

Saskatchewan System Shipper Complaint

On December 17, 2010, the Saskatchewan System filed amended Westspur tariffs with the NEB with an effective date of February 1, 2011. In January 2011, a shipper on the Westspur System requested the NEB make the tolls “interim” effective February 1, 2011 pending discussions between the shipper and the Saskatchewan System on information requests put forward by the shipper. Subsequently, the shipper

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filed a complaint with the NEB on the basis the information provided by the Saskatchewan System was not adequate to allow for an assessment to be made of the reasonableness of the tolls. Six parties have filed letters with the NEB supporting the shipper’s complaint. The NEB directed additional discussion among the parties and, as of August 1, 2012, the Fund continues to review the structure of its Westspur tolls with shippers.

CORPORATE

Noverco

Noverco Inc. (Noverco) holds, directly and indirectly, an investment in Enbridge common shares. In early 2012, Noverco advised Enbridge that the substantial increase in the value of these shares over the last decade resulted in a significant shift in the balance of Noverco’s asset mix. The Board of Directors of Noverco authorized the Caisse de Depot et Placement de Quebec, as manager of Noverco, to sell a portion of its Enbridge common share holding and rebalance Noverco’s asset mix. On March 22, 2012, Noverco sold 22.5 million Enbridge common shares through a secondary offering. Enbridge’s share of the proceeds of approximately $317 million was received as a dividend from Noverco on May 18, 2012 and was used to pay a portion of the Company’s quarterly dividend on June 1, 2012. This portion of the quarterly dividend did not qualify for the enhanced dividend tax credit in Canada and accordingly, was not designated as an “eligible dividend”. For United States tax purposes, the dividend was a “qualified dividend”.

Preference Share Issuances

Since January 1, 2012 the Company has issued 76 million preference shares for gross proceeds of approximately $1,910 million with the following characteristics. See Outstanding Share Data.

Common Share Issuance

On June 8, 2012, the Company issued 9.83 million Common Shares for gross proceeds of approximately $400 million.

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GROWTH PROJECTS

The table below summarizes the current status of the Company’s commercially secured projects in each of the Company’s business segments.

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LIQUIDS PIPELINES

Edmonton Terminal Expansion

The Edmonton Terminal Expansion Project involves expanding the tankage of the mainline terminal at Edmonton, Alberta by one million barrels at an estimated cost of $0.3 billion, with expenditures to date of approximately $0.1 billion. The expansion is required to accommodate growing oil sands production receipts both from Enbridge’s Waupisoo Pipeline and other non-Enbridge pipelines. The expansion will be conducted over two phases and will consist of the construction of four tanks and the installation of three booster pumps and related infrastructure. Regulatory approval was received in the first quarter of 2011 and the expansion is expected to be completed by December 2012.

Woodland Pipeline

Enbridge entered into a joint venture agreement with Imperial Oil Resources Ventures Limited and ExxonMobil Canada Properties to provide for the transportation of blended bitumen from the Kearl oil sands mine to crude oil hubs in the Edmonton, Alberta area. The project will be phased with the mine expansion, with the first phase involving construction of a new 140-kilometre (87-mile) 36-inch diameter pipeline from the mine to the Cheecham Terminal, and service on Enbridge’s existing Waupisoo Pipeline from Cheecham to the Edmonton area. The new Woodland Pipeline may be extended from Cheecham to Edmonton as part of future industry expansions. Regulatory approval for the Phase I facilities was received in June 2010 and construction is substantially complete. The total estimated cost of the Phase I pipeline from the mine to the Cheecham Terminal and related facilities is approximately $0.5 billion, of which Enbridge’s share is approximately $0.3 billion. Enbridge’s share of total project expenditures to date is approximately $0.2 billion. Enbridge expects the pipeline will come into service in late 2012.

Wood Buffalo Pipeline

Enbridge entered into an agreement with Suncor Energy Inc. (Suncor) to construct a new, 95-kilometre (59-mile) 30-inch diameter crude oil pipeline, connecting the Athabasca Terminal adjacent to Suncor’s oil sands plant to the Cheecham Terminal, which is the origin point of Enbridge’s Waupisoo Pipeline. The Waupisoo Pipeline already delivers crude oil from several oil sands projects to crude oil hubs in the Edmonton, Alberta area. The new Wood Buffalo Pipeline will parallel the existing Athabasca Pipeline between the Athabasca and Cheecham Terminals. The estimated capital cost is approximately $0.4 billion, with expenditures to date of approximately $0.3 billion. Construction of the pipeline was

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substantially completed in the first quarter of 2012, with in service expected by late 2012 upon completion of the related station facilities.

Waupisoo Pipeline Capacity Expansion

The Waupisoo Pipeline Capacity Expansion, which received regulatory approval in November 2010, is expected to provide 65,000 bpd of additional capacity in the second half of 2012 and an estimated 190,000 bpd of additional capacity in the second half of 2013 when the expansion is fully in service. The estimated cost of the project is approximately $0.4 billion, with expenditures to date of approximately $0.2 billion.

Seaway Crude Pipeline System

Acquisition of Interest

In 2011, Enbridge acquired a 50% interest in the Seaway Pipeline system at a cost of approximately US$1.2 billion. The 1,078-kilometre (670-mile) Seaway Pipeline includes the 805-kilometre (500-mile), 30-inch diameter long-haul system from Freeport, Texas to Cushing, Oklahoma, as well as the Texas City Terminal and Distribution System which serves refineries in the Houston and Texas City areas. The Seaway Pipeline also includes 6.8 million barrels of crude oil tankage on the Texas Gulf Coast and four marine import facilities at two locations. The other 50% interest in the Seaway Pipeline system is owned by Enterprise Products Partners L.P. (Enterprise).

Reversal

In December 2011, Enbridge and Enterprise announced plans to reverse the flow direction of the Seaway Pipeline, enabling it to transport crude oil from the oversupplied hub in Cushing, Oklahoma to the United States Gulf Coast. Included in the project scope is a 105-kilometre (65-mile), 36-inch new-build lateral from the Seaway Jones Creek facility southwest of Houston, Texas into Enterprise’s ECHO crude oil terminal (ECHO Terminal) southeast of Houston. The reversal of the pipeline and acceptance of first crude was completed in May 2012, providing initial capacity of 150,000 bpd.  Following pump station additions and modifications, which are expected to be completed by the first quarter of 2013, capacity would increase to 400,000 bpd depending upon the mix of light and heavy grades of crude oil. Enbridge’s expected cost for the reversal is approximately US$0.2 billion.

Expansion and Extension

In March 2012, Enbridge and Enterprise, based on additional capacity commitments from shippers, announced plans to proceed with an expansion of the Seaway Pipeline through construction of a second line that will more than double its capacity to 850,000 bpd by mid-2014. This 30-inch diameter pipeline, which will follow the same route, will twin the existing Seaway system.

In addition, a 137-kilometre (85-mile) pipeline will be constructed from the ECHO Terminal to the Port Arthur/Beaumont, Texas refining center to provide shippers access to the region’s heavy oil refining capabilities. This lateral will offer capacity of 560,000 bpd and, subject to regulatory approvals, is expected to be available in early 2014. Enbridge’s investment to twin the pipeline and for the Port Arthur lateral is expected to be approximately US$1.0 billion.

South Cheecham Rail and Truck Terminal

The Company has partnered with Keyera Corp. to construct the South Cheecham Rail and Truck Terminal (the Terminal), located approximately 75 kilometres (47 miles) southeast of Fort McMurray, Alberta. The Terminal, to be developed in phases, will be a multi-purpose hydrocarbon rail and truck terminal, designed to support bitumen producers within the Athabasca oil sands area. In addition to the facilities for handling diluent and diluted bitumen at the Terminal, the initial phase is planned to include a diluted bitumen pipeline connection to Enbridge’s existing Cheecham terminal. Completion of the first phase is expected to take place in the first half of 2013 for a total cost of approximately $90 million. Enbridge’s share of the project costs will be based upon its 50% joint venture interest.

Norealis Pipeline

In order to provide pipeline and terminaling services to the proposed Husky-operated Sunrise Oil Sands Project, the Company is undertaking construction of a new originating terminal (Norealis Terminal), a

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112-kilometre (66-mile) 24-inch diameter pipeline (Norealis Pipeline) from the Norealis Terminal to the Cheecham Terminal, and additional tankage at Cheecham. The estimated cost of the project is approximately $0.5 billion, with expenditures to date of approximately $0.1 billion. With regulatory approval received in the second quarter of 2011, the project is expected to be in service in late 2013.

Athabasca Pipeline Capacity Expansion

The Company is undertaking an expansion of its Athabasca Pipeline to its full capacity to accommodate additional contractual commitments, including incremental production from the Christina Lake Oilsands Project operated by Cenovus Energy. This expansion is expected to increase the capacity of the Athabasca Pipeline to its maximum capacity of approximately 570,000 bpd, depending on the mix of crude oil types. The estimated cost of full expansion is approximately $0.4 billion, with expenditures to date of approximately $0.1 billion and an expected in-service date in the first quarter of 2013, for an initial 430,000 bpd of capacity.  The balance of additional capacity is expected to be available by early 2014. The Athabasca Pipeline transports crude oil from various oil sands projects to the mainline hub at Hardisty, Alberta.

Flanagan South Pipeline Project

The 950-kilometre (590-mile) Flanagan South Pipeline will have an initial capacity of 585,000 bpd to transport crude oil from the Company’s terminal at Flanagan, Illinois to Cushing, Oklahoma.  The 36-inch diameter pipeline will be installed adjacent to the Company’s Spearhead Pipeline for the majority of the route.  Subject to regulatory and other approvals, the pipeline is expected to be in service by mid-2014. The estimated cost of the project is approximately US$2.8 billion. Both the Seaway and Flanagan South pipelines are included in the Company’s Gulf Coast Access initiative to offer crude oil transportation from its terminal at Flanagan to the United States Gulf Coast.

Canadian Mainline Expansion

On May 16, 2012, Enbridge announced an estimated $0.2 billion expansion of the Alberta Clipper line between Hardisty, Alberta and the Canada/United States border near Gretna, Manitoba.  The current scope of the project, which supports the Company’s Gulf Coast Access initiative, will involve the addition of pumping horsepower sufficient to raise the capacity of the Canadian mainline by 120,000 bpd and is expected to be in service by mid-2014.  The expansion remains subject to NEB approval.

Athabasca Pipeline Twinning

This project involves the twinning of the southern section of the Company’s Athabasca Pipeline from Kirby Lake, Alberta to the Hardisty, Alberta crude oil hub to provide additional capacity to serve expected oil sands growth in the Kirby Lake producing region. The expansion project, with an estimated cost of approximately $1.2 billion, will include 345 kilometres (210 miles) of 36-inch pipeline within the existing Athabasca Pipeline right-of-way. The initial annual capacity of the twin pipeline will be approximately 450,000 bpd, with expansion potential to 800,000 bpd. Subject to regulatory approvals, the line is expected to enter service in 2015.

Northern Gateway Project

The Northern Gateway Project involves constructing a twin 1,177-kilometre (731-mile) pipeline system from near Edmonton, Alberta to a new marine and tank terminal in Kitimat, British Columbia. One pipeline would transport crude oil for export from the Edmonton area to Kitimat and is proposed to be a 36-inch diameter line with an initial capacity of 525,000 bpd. The other pipeline would be used to import condensate and is proposed to be a 20-inch diameter line with an initial capacity of 193,000 bpd.

Northern Gateway submitted an application to the NEB in May 2010. The Joint Review Panel (JRP) established to review the proposed project, pursuant to the NEB Act and the Canadian Environmental Assessment Act, has a broad mandate to assess the potential environmental effects of the project and to determine if it is in the public interest. Following sessions with the public, including Aboriginal groups, and the provision of additional information by Northern Gateway, the JRP issued a Hearing Order in May 2011 outlining the procedures to be followed.

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In August 2011, Northern Gateway filed commercial agreements with the NEB which provide for committed long-term service and capacity on both the proposed crude oil export and condensate import pipelines. Capacity has also been reserved for use by uncommitted shippers.

In the fall of 2011, Northern Gateway responded to written questions by interveners and government participants.

In a Procedural Direction issued in December 2011, the JRP indicated community hearings would be scheduled so the Panel would hear all oral evidence from registered interveners first, followed by oral statements from registered participants. Community hearings for oral evidence and statements took place between January and June 2012 in various communities. The JRP has now collected more than 90% of the oral evidence and 70% of the oral statements in locations which the proposed project passes. A written record of what was said each day in the community hearings is available on the Panel’s website. Interveners responded to questions by Northern Gateway on July 6, 2012. Northern Gateway filed reply evidence to the evidence of the interveners on July 20, 2012. The Panel has scheduled final hearings commencing on September 4, 2012 through to December 2012 where Northern Gateway, interveners, government participants and the JRP will question those who have presented oral or written evidence.

Following the final hearings and prior to Final Argument, the Panel will hear additional oral statements from interested parties who do not reside along the pipeline corridor or shipping routes. Final Argument is proposed for March and April 2013. Based on this projected schedule, the JRP expects to issue its reports and findings on the proposed project by December 2013. Of the 45 Aboriginal groups eligible to participate as equity owners, 26 have signed up to do so. Subject to continued commercial support, regulatory and other approvals, and adequately addressing landowner and local community concerns (including those of Aboriginal communities), the Company currently estimates that Northern Gateway could be in service in 2017 at the earliest. Expenditures to date, which relate primarily to the regulatory process, are approximately $0.3 billion, of which approximately half is secured in funding from Western Canada producers and Pacific Rim refiners toward the costs of seeking the necessary regulatory approvals for the project. Given the many uncertainties surrounding the Northern Gateway Project, including final ownership structure, the potential financial impact of the project cannot be determined at this time.

On February 23, 2012, Transport Canada published its TERMPOL Review Process Report of the Northern Gateway Project’s proposed marine operations. Transport Canada has filed the results of the study with the federal JRP tasked with assessing the project. The study reviewed the marine operations associated with the Northern Gateway terminal and associated tanker traffic in Canadian waters. The review concluded that: “While there will always be residual risk in any project, after reviewing the proponent’s studies and taking into account the proponent’s commitments, no regulatory concerns have been identified for the vessels, vessel operations, the proposed routes, navigability, other waterway users and the marine terminal operations associated with vessels supporting the Northern Gateway Project.” The TERMPOL report was prepared and approved by Canadian government authorities including Transport Canada; Environment Canada; Fisheries and Oceans Canada; Canadian Coast Guard; and Pacific Pilotage Authority Canada. Further review of the Northern Gateway application by the JRP, as well as other agencies, is ongoing.

As noted above, Northern Gateway filed reply evidence with the JRP on July 20, 2012 which contained details of further enhancements in pipeline design and operations. These extra measures, estimated to cost an additional $400 million to $500 million, for a total estimated project cost of approximately $5.9 billion to $6.0 billion, include: increasing pipeline wall thickness of the oil pipeline; additional pipeline wall thickness for water crossings such as major tributaries to the Fraser, Skeen and Kitimat Rivers; increasing the number of remotely-operated isolation valves by 50% within British Columbia to protect high-value fish habitat; increasing frequency of in-line inspection surveys across the entire pipeline system by a minimum 50% over and above current standards; installing dual leak detection systems; and staffing pump stations in remote locations on a 24 hour / 7 day basis for on-site monitoring, heightened security and rapid response to abnormal conditions.

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The JRP posts public filings related to Northern Gateway on its website at http://gatewaypanel.review-examen.gc.ca/clf-nsi/hm-eng.html and Enbridge also maintains a Northern Gateway Project website in addition to information available on www.enbridge.com. The full regulatory application submitted to the NEB and the 2010 Enbridge Northern Gateway Community Social Responsibility Report are available on www.northerngateway.ca. None of the information contained on, or connected to, the JRP website, the Northern Gateway Project website or Enbridge’s website is incorporated in or otherwise part of this MD&A.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Silver State North Solar Project

In March 2012, Enbridge acquired a 100% interest in the development of the 50-megawatt (MW) Silver State North Solar Project (Silver State), located 65 kilometres (40 miles) south of Las Vegas, Nevada. The project, which began commercial operation in May 2012, was constructed under a fixed-price engineering, procurement and construction agreement with First Solar. First Solar is providing operations and maintenance services under a long-term contract. Energy output is being delivered to NV Energy, Inc.under a 25-year power purchase agreement (PPA). The Company’s total investment in the project was approximately US$0.2 billion.

Lac Alfred Wind Project

Enbridge secured a 50% interest in the development of the 300-MW Lac Alfred Wind Project (Lac Alfred), located 400 kilometres (250 miles) northeast of Quebec City in Quebec’s Bas-Saint-Laurent region. The project is being constructed under a fixed price, turnkey, engineering, procurement and construction agreement and will take place in two phases: Phase 1 is expected to be completed in December 2012; while Phase 2 is expected to be completed in December 2013. Hydro-Quebec will purchase the power under a 20-year PPA and will construct the 30-kilometre transmission line to connect Lac Alfred to the grid under an interconnection agreement. The Company’s total investment in the project is expected to be approximately $0.3 billion, with expenditures to date of approximately $0.2 billion.

Cabin Gas Plant

In 2011, the Company secured a 71% interest in the development of the Cabin Gas Plant (Cabin), located 60 kilometres (37 miles) northeast of Fort Nelson, British Columbia in the Horn River Basin. The Company’s total investment in phases 1 and 2 of Cabin is expected to be approximately $1.1 billion, with expenditures to date of approximately $0.6 billion. Phase 1 of the development is to have 400 million cubic feet per day (mmcf/d) of processing capacity. The plant is currently under construction and is expected to be in service in late 2012. Capacity for both phases 1 and 2 has been fully subscribed by Horn River producers. These producers can request the Company to expand Cabin up to an additional four phases, under agreed terms.

Tioga Lateral Pipeline

Alliance Pipeline US plans to develop a natural gas pipeline lateral and associated facilities to connect production from the Hess Tioga field processing plant in the Bakken region of North Dakota to the Alliance mainline near Sherwood, North Dakota. Through its 50% ownership interest in Alliance Pipeline US, Enbridge’s expected cost related to the project is approximately US$0.1 billion. Alliance Pipeline US has executed a precedent agreement with Hess Corporation (Hess) as an anchor shipper on the Tioga Lateral Pipeline. Aux Sable Liquids Products (Aux Sable) and Hess have reached a concurrent agreement for the provision of NGL services. The 124-kilometre (77-mile) Tioga Lateral Pipeline will facilitate movement of high-energy, liquids-rich natural gas to NGL processing facilities owned by Aux Sable at the terminus of the Alliance mainline system. The pipeline will have an initial design capacity of approximately 106 mmcf/d, which can be expanded based on shipper demand. On January 25, 2012, Alliance Pipeline US filed an application for regulatory approval to construct and operate the Tioga Lateral and, pending approvals, the pipeline is expected to be in service by mid-2013.

Venice Condensate Stabilization Facility

The Company is carrying out an estimated US$0.2 billion expansion of the Venice Condensate Stabilization Facility (Venice) at its Venice, Louisiana facility within its Offshore business. The expanded condensate processing capacity is required to accommodate additional natural gas production from the

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Olympus offshore oil and gas development. Natural gas production from Olympus will move to Enbridge’s onshore facility at Venice via Enbridge’s Mississippi Canyon offshore pipeline system where it will be processed to separate and stabilize the condensate. The expansion, which is expected to more than double the capacity of the facility to approximately 12,000 barrels of condensate per day, is expected to be in service in late 2013.

Walker Ridge Gas Gathering System

The Company executed definitive agreements in 2010 with Chevron USA, Inc. (Chevron) and Union Oil Company of California to expand its central Gulf of Mexico offshore pipeline system. Under the terms of the agreements, Enbridge will construct, own and operate the Walker Ridge Gas Gathering System (WRGGS) to provide natural gas gathering services to the proposed Jack, St. Malo and Big Foot ultra-deep water developments. The WRGGS includes 274 kilometres (170 miles) of 8-inch or 10-inch diameter pipeline at depths of up to approximately 2,150 meters (7,000 feet) with capacity of 0.1 billion cubic feet per day. WRGGS is expected to be in service in 2014 and is expected to cost approximately US$0.4 billion, with expenditures to date of approximately US$0.1 billion.

Big Foot Oil Pipeline

The Company executed definitive agreements in 2011 with Chevron, Statoil Gulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc. to construct and operate a 64-kilometre (40-mile) 20-inch oil pipeline with capacity of 100,000 bpd from the proposed Big Foot ultra-deep water development in the Gulf of Mexico. This crude oil pipeline project is complementary to Enbridge’s plans to construct the WRGGS. The estimated cost of the Big Foot Oil Pipeline, which will be located about 274 kilometres (170 miles) south of the coast of Louisiana, is approximately US$0.2 billion, with expenditures to date of approximately US$0.1 billion, and it is expected to be in service in 2014.

SPONSORED INVESTMENTS

Bakken Expansion Program

A joint project to further expand crude oil pipeline capacity to accommodate growing production from the Bakken and Three Forks formations located in Montana, North Dakota, Saskatchewan and Manitoba is being undertaken by EEP and the Fund. The Bakken Expansion Program is expected to provide capacity of 145,000 bpd. The Bakken Expansion Program involves United States projects undertaken by EEP at a cost of approximately US$0.4 billion and Canadian projects undertaken by the Fund at a cost of approximately $0.2 billion. Regulatory approval has been received and construction commenced in July 2011 on the United States portion of the project, with expenditures to date of approximately US$0.1 billion. In Canada, NEB approval was secured in December 2011. Subject to other approvals in respect of the Canadian portion, the Bakken Expansion Program is expected to be completed in the first quarter of 2013.

Enbridge Energy Partners, L.P.

Cushing Terminal Storage Expansion Project

EEP is constructing 13 new storage tanks at its Cushing Terminal with an approximate shell capacity of 4.4 million barrels. To date, nine tanks have been completed and placed into service, with the remaining four tanks expected to come into service by December 2012.

In July 2012, engineering design commenced on three new tanks and associated infrastructure totaling 770,000 barrels of incremental working capacity at EEP’s Cushing Terminal, at an estimated cost of US$39 million, bringing the total estimated cost of the expansion to approximately US$0.2 billion, with expenditures to date of approximately US$0.1 billion. The expected in-service date for the three tanks is August 2013.

South Haynesville Shale Expansion

EEP is expanding its East Texas system by constructing three lateral pipelines into the East Texas portion of the Haynesville shale, together with a large diameter lateral pipeline from Shelby County to Carthage. The expansion, completed in the second quarter of 2012 at an approximate cost of US$0.1 billion, increased capacity of EEP’s East Texas system by 900 mmcf/d.

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EEP plans to invest an additional US$0.2 billion, with expenditures to date of approximately US$0.1 billion, to expand its East Texas system, including the construction of gathering and related treating facilities. EEP has signed long-term agreements with four major natural gas producers along the Texas side of the Haynesville shale to provide gathering, treating and transmission services. Completion of the additional expansion is dependent on drilling plans of these producers. Due to lower levels of producer activity, in light of weak gas prices, EEP has deferred portions of its Haynesville natural gas expansion pending increases in drilling activity.

Berthold Rail Project

EEP is proceeding with the Berthold Rail Project, a US$0.1 billion investment that will provide an interim solution to shipper needs in the Bakken region. The project is expected to expand capacity into the Berthold Terminal by 80,000 bpd and includes the construction of a three-unit train loading facility, crude oil tankage and other terminal facilities adjacent to existing infrastructure, with an expected in-service date by early 2013.

Ajax Cryogenic Processing Plant

EEP is constructing an additional processing plant and other facilities on its Anadarko System at an approximate cost of US$0.2 billion, with expenditures to date of approximately US$0.1 billion. The Ajax Plant, with a planned capacity of 150 mmcf/d, is expected to be in service in early 2013. When operational, the Ajax Plant in conjunction with the Allison Plant, is expected to increase total processing capacity on the Anadarko System to approximately 1,200 mmcf/d.

Bakken Access Program

The Bakken Access Program, a series of projects totaling approximately US$0.1 billion, represents an upstream expansion that will further complement EEP’s Bakken expansion. This expansion program will enhance gathering capabilities on the North Dakota System by 100,000 bpd. The program, which involves increasing pipeline capacities, constructing additional storage tanks and adding truck access facilities at multiple locations in western North Dakota, is expected to be in service by early 2013.

Texas Express Pipeline

The Texas Express Pipeline (TEP) is a joint venture with Enterprise, Anadarko Petroleum Corporation and DCP Midstream LLC to design and construct a new NGL pipeline, as well as two new NGL gathering systems which EEP will build and operate. EEP will invest approximately US$0.4 billion in the TEP, which will originate in Skellytown, Texas and extend approximately 935 kilometres (580 miles) to NGL fractionation and storage facilities in Mont Belvieu, Texas. TEP is expected to have an initial capacity of approximately 280,000 bpd and will be expandable to approximately 400,000 bpd. Approximately 250,000 bpd of capacity has been subscribed on the pipeline.

One of the new NGL gathering systems will connect TEP to natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma, while the second will connect TEP to central Texas Barnett Shale processing plants. Subject to regulatory approvals and finalization of commercial terms, the pipeline and portions of the gathering systems are expected to begin service in mid-2013.

Line 6B Replacement Program

This program includes the replacement of 120 kilometres (75 miles) of non-contiguous sections of Line 6B of EEP’s Lakehead System. The Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. The new segments are targeted to be placed in service by the first quarter of 2013 in consultation with, and to minimize impact to, refiners and shippers served by Line 6B crude oil deliveries. These costs will be recovered through EEP’s tariff surcharge that is part of the system-wide rates of the Lakehead System. The total capital for this replacement program is estimated to be US$0.3 billion, with expenditures to date of approximately US$0.1 billion.

Eastern Access Expansion

As previously announced in 2011, Enbridge and EEP will undertake two projects to provide increased access to refineries in the United States upper mid-west and in Ontario for light crude oil produced in

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western Canada and the United States. One project involves the expansion of EEP’s Line 5 light crude oil line between Superior, Wisconsin and Sarnia, Ontario by 50,000 bpd, at a cost of approximately US$0.1 billion. Complementing the Line 5 expansion, Enbridge plans to reverse a portion of its Line 9 (Line 9A) in western Ontario to permit crude oil movements eastbound from Sarnia as far as Westover, Ontario at a cost of approximately $20 million. Subject to regulatory approvals, the Line 5 expansion is targeted to be in service during the first quarter of 2013. In July 2012, the NEB approved the Line 9A reversal which is expected to be in service in late 2013.

On May 16, 2012, Enbridge announced that it had secured commercial support to proceed with additional Eastern Access projects. Enbridge and EEP also expect to proceed with supporting expansions of the United States mainline system between Flanagan, Illinois and Sarnia, Ontario. The additional Eastern Access projects include an 80,000 bpd expansion of Enbridge’s Toledo Pipeline (Line 17), which connects with the Enbridge mainline at Stockbridge, Michigan and serves refineries at Toledo, Ohio and Detroit, Michigan, and a reversal of Enbridge’s 240,000 bpd Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in Quebec. Sufficient capacity has been requested by refineries seeking to secure access to ample crude oil supplies from western Canada and the Bakken region in North Dakota to warrant proceeding with the project. The Eastern Access Line 9B reversal remains subject to NEB regulatory approval.

The Toledo Pipeline expansion is expected to be available for service in early 2013 at a cost of approximately US$0.2 billion.  The Line 9B reversal is expected to be available for service in early 2014 at a cost of approximately $0.3 billion. Both the Toledo Pipeline and Line 9 assets are included in the Company’s Liquids Pipelines segment.

The supporting mainline expansions include expansion of the Spearhead North pipeline (Line 62) between Flanagan and Griffith, Indiana, an additional 330,000 barrel tank at Griffith and the replacement of additional sections of Line 6B in Indiana and Michigan not already scheduled for replacement as previously announced. The capacity of Spearhead North will increase by 105,000 bpd and the capacity of Line 6B will increase by 260,000 bpd. The expected cost of the mainline expansions is US$2.2 billion, including the US$0.1 billion cost of the previously announced Line 5 expansion. In addition, the supporting mainline expansions will be funded 60% by Enbridge and 40% by EEP, with EEP having the option to reduce its funding and associated economic interest in the projects by up to 15% before the end of 2012. Furthermore, within one year of the in-service date, scheduled for early 2014, EEP will also have the option to increase its economic interest held at that time by up to 15%.

Lakehead System Mainline Expansion

On May 16, 2012, EEP announced several projects to expand capacity of the Lakehead System mainline between its origin at the Canada/United States border, near Neche, North Dakota, to Flanagan, Illinois. The current scope of the projects includes expansion of the Alberta Clipper line between the border and Superior, Wisconsin from 450,000 bpd to 570,000 bpd, and expansion of the Southern Access line between Superior and Flanagan, Illinois from 400,000 bpd to 560,000 bpd. The projects require only the addition of pumping horsepower, with no line pipe construction. Alberta Clipper and Southern Access are both held in Enbridge Energy, Limited Partnership (EELP), which will be fully funded by EEP for the cost of the expansions.  The scope of the expansions remains under discussion, which could lead to an upward revision to capacity and cost.

Subject to finalization of scope, the expansions will be undertaken by EELP on a full cost-of-service basis, and are expected to be available for service in mid-2014 at an estimated cost of US$0.4 billion. The expansions are designed to accommodate increased throughput on the Lakehead System for deliveries to Enbridge’s Gulf Coast Access initiative, as well as growth in Chicago area refinery requirements.  These expansions are incremental to those undertaken as part of the Eastern Access expansion.

CORPORATE

Montana-Alberta Tie-Line

Montana-Alberta Tie-Line (MATL) is a 345-kilometre (215-mile) transmission line from Great Falls, Montana to Lethbridge, Alberta, designed to take advantage of the growing supply of electric power in

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Montana and buoyant power demand in Alberta. The total expected cost for both the first 300-MW phase of MATL and the expansion for an additional 250-MW to 300-MW has been increased to approximately US$0.4 billion, with expenditures to date of approximately US$0.3 billion. While the permits required for construction have been obtained, the Alberta Utility Commission’s approval in Canada is currently being updated to reflect a number of design modifications and on-going consultation with land owners. Subject to this approval, the system’s north-bound capacity, which is fully contracted, is expected to be in service in the fourth quarter of 2012, with the expansion expected to be completed by the end of 2014.

Neal Hot Springs Geothermal Project

The Company has partnered with U.S. Geothermal Inc. (U.S. Geothermal) to develop the 35-MW (22-MW, net) Neal Hot Springs Geothermal Project located in Malheur County, Oregon. U.S. Geothermal is constructing the plant and will operate the facility. Completion of the project has been extended to the end of 2012 and, once operational, the facility will deliver electricity to the Idaho Power grid under a 25-year PPA. Enbridge will invest up to approximately US$33 million for a 41% interest in the project.

FINANCIAL RESULTS

LIQUIDS PIPELINES

Canadian Mainline earnings for the first six months of 2012 were governed by the CTS (with the exception of Lines 8 and 9), whereas earnings for the first six months of 2011 were governed by a series of agreements, the most significant being the Incentive Tolling Settlement applicable to the mainline system and the Terrace and Alberta Clipper agreements. Earnings under the CTS are subject to variability in throughput volume and operating costs. Canadian Mainline volumes during the first half of 2012 were higher than expected contributing to an increase in earnings relative to the prior year, partially offset by higher operating and administrative costs, primarily due to higher employee related costs, higher leak repairs and the timing of integrity work. Incremental oil sands crude production in Alberta and strong production growth out of the Bakken in North Dakota have bolstered supply to midwest markets, and placed increased downward pressure on crude oil prices in the midwest, pending completion of Enbridge’s market access projects. This discounted crude oil, coupled with strong refining margins, is increasing demand in the midwest for Canadian and Bakken crude oil supply and driving increased long haul barrels on Canadian Mainline and EEP’s Lakehead System.

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Supplemental information on Canadian Mainline adjusted earnings for the three and six months ended June 30, 2012 is as follows:

Canadian Mainline revenues included the portion of the system covered by the CTS as well as revenues from Lines 8 and 9 in eastern Canada. Line 8 and Line 9 are currently tolled on a separate basis and comprise a relatively small proportion of total Canadian Mainline revenues. CTS revenues include transportation revenues, the largest component, as well as allowance oil and revenues from receipt and delivery charges. Transportation revenues include revenues for volumes delivered off the Canadian Mainline at Gretna and on to the Lakehead System, to which Canadian Mainline IJT residual tolls apply, and revenues for volumes delivered to other western Canada delivery points, to which the Canadian Local Toll (CLT) applies. Despite the many factors which affect Canadian Mainline revenues, the primary determinants of those revenues will be throughput volume ex-Gretna, the United States dollar Canadian Mainline IJT residual benchmark toll and the effective foreign exchange rate at which resultant revenues are converted into Canadian dollars. The Company may utilize derivative financial instruments to hedge foreign exchange rate risk on United States dollar denominated revenues. The exact relationship between the primary determinants and actual Canadian Mainline revenues will vary somewhat from quarter to quarter but is expected to be relatively stable on average for a year, absent a systematic shift in receipt and delivery point mix or in crude oil type mix.

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The largest components of operating and administrative expenses are employee related costs, pipeline integrity, repairs and maintenance, rents and leases and property taxes. Operating and administrative costs are relatively insensitive to throughput volumes. The primary drivers of future increases in operating costs are expected to be normal escalation in wage rates, prices for purchased services and tax rates, the addition of new facilities and more extensive integrity and maintenance programs.

Power is the most significant variable operating cost and is subject to variations in operating conditions, including system configuration, pumping patterns and pressure requirements. However, the primary determinants of power cost are the level of power prices in various jurisdictions and throughput volume. The relationship of power consumption to throughput volume is expected to be roughly proportional over a moderate range of volumes. The Company may utilize derivative financial instruments to hedge power prices.

Depreciation and amortization expense will adjust over time as a result of changes in estimated depreciation rates and additions to property, plant and equipment due to new facilities, as well as maintenance and integrity capital expenditures.

Canadian Mainline income taxes reflect current income taxes only. Under the CTS, the Company retains the ability to recover deferred income taxes under an NEB order governing flow-through income tax treatment and, as such, an offsetting regulatory asset related to deferred income taxes is recognized as incurred.

The preceding financial overview includes expectations regarding future events and operating conditions that the Company believes are reasonable based on currently available information; however, such statements are not guarantees of future performance and are subject to change.

Prior to the implementation of the CTS, revenue on the Canadian Mainline was recognized in a manner consistent with the underlying agreements as approved by the regulator, in accordance with rate-regulated accounting. The Company discontinued the application of rate-regulated accounting to its Canadian Mainline (excluding Lines 8 and 9) on a prospective basis commencing July 1, 2011. The regulatory asset balance at the date of discontinuance related to tolling deferrals recognized in prior periods is being recovered through a surcharge to the CLT and IJT. While the CTS is based on previous tolling settlements and cost-of-service principles, earnings are subject to variability associated with throughput volume and capital and operating costs, subject to various protection mechanisms. As a result, the Canadian Mainline operations (excluding Lines 8 and 9) no longer meet all of the criteria required for the continued application of rate-regulated accounting treatment. The regulatory asset of approximately $470 million related to deferred income taxes recorded at the date of discontinuance will continue to be recognized as the Company retains the ability to recover deferred income taxes under an NEB order governing flow-through income tax treatment. In the same manner, the rate order provides for the recovery of deferred income taxes incurred subsequent to the date of discontinuance and, as such, regulatory assets related to deferred income taxes will continue to be recognized as incurred.

Regional Oil Sands System earnings for the first six months of 2012 decreased primarily as a result of higher operating and administrative expenses partially offset by higher shipped volumes and increased tolls on the Athabasca Pipeline.

Spearhead Pipeline adjusted earnings increased as a result of higher volumes and tolls, as well as the recognition of expired shipper make-up rights compared with prior year. Volumes significantly increased over 2011 due to increased demand at Cushing, Oklahoma in anticipation of additional capacity on the Seaway Pipeline for further transportation to the United States Gulf Coast.

The earnings increase in Feeder Pipelines and Other, which includes the Seaway Pipeline, primarily reflected a higher contribution from Olympic Pipeline resulting from a tariff increase, as well as higher volumes on Toledo Pipeline. In 2011, earnings from Toledo Pipeline were negatively impacted by integrity work on Lines 6A and 6B of EEP’s Lakehead System.

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Liquids Pipelines earnings were impacted by the following non-recurring or non-operating adjusting items.

·                  Canadian Mainline earnings for 2011 included $14 million from the settlement of a shipper dispute related to oil measurement adjustments in prior years.

·                  Canadian Mainline earnings included a Line 9 tolling adjustment related to services provided in prior periods.

·                  Canadian Mainline earnings reflected unrealized fair value gains and losses on derivative financial instruments used to risk manage exposures inherent within the CTS, namely foreign exchange, power cost variability and allowance oil commodity prices.

·                  Spearhead Pipeline earnings included unrealized fair value gains on derivative financial instruments used to manage exposures to allowance oil commodity prices.

GAS DISTRIBUTION